Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2023 Second Quarter Results Conference Call. As a reminder, today's call is being recorded. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thanks, Michelle, and welcome, everyone, to our second quarter '23 conference call. This call is being webcast and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the beginning of our slides and in our disclosure documents filed on SEDAR and EDGAR. Following prepared remarks, we will be available to take your questions. Please limit your time to one question and one follow-up. I will now turn the call over to our President and CEO, Brendan McCracken.

Good morning. Thank you for joining us. Our outstanding second quarter results continue the strong momentum we've created with our focus on execution, and making better wells for lower costs. We exceeded every one of our guidance targets on the quarter. We also closed two compelling transactions that have simplified our portfolio, extended our premium inventory, enhanced our go-forward capital efficiency, and expanded our margins. I'll speak more to the progress we are making with the newly acquired Permian assets in a moment, but first, I want to touch on our second quarter results. Our production outperformance in the quarter is coming from our legacy business. The accelerated close was included with our previously issued 2Q guidance, and the new assets have performed right in line with our expectations during the quarter. The quarter was a beat across the board from production to capital to per unit costs. We exceeded our targets and delivered on both efficiencies and well productivity. Greg will cover this in more detail in a moment, but our oil production outperformance is the result of our completion design innovations, and our capital reductions are the result of our execution efficiency gains. As a result, we've raised our full year production guidance and lowered our full year capital guide. Across the portfolio, the intense focus our teams have placed on operational execution continues to deliver results, especially in the Permian, where we posted another quarter of record operational efficiencies. Our Permian team has seamlessly integrated the new assets into our existing operations. We were pleased to close the transaction early and we’ve already finished resetting activity on the new acreage. We are currently at our expected run rate activity for the rest of the year with five rigs and three completion crews in the Permian. We are also already executing our proven drilling and completion designs on our new assets, and we fully expect to have our first fully Ovintiv designed wells online later in the fourth quarter. On second quarter production, we exceeded the top end of our guidance on oil, gas, and NGLs, while coming in below the low end of guidance for capital. These results were driven by strong well performance from each asset in our portfolio, successful base decline management on our older vintage wells, tailwinds from lower natural gas royalty rates in the Montney, and capital savings from continued record-setting operational performance across the asset base. We also returned approximately $172 million to our shareholders through share buybacks and our recently increased base dividend. I'll now turn the call over to Corey to cover our financial results.

Thanks, Brendan, and good morning. In addition to the great operational results Brendan outlined, we also delivered strong financial results in the quarter with earnings per share of $1.34 and cash flow per share of $2.79, beating consensus estimates. We remain free cash flow positive despite the impact of transaction-related costs and the incremental capital associated with the early close of the Permian Basin acquisition. We also saw strong per unit cost performance with operating expense, transportation, processing expense, and production, mineral, and other taxes coming in below the midpoint of guidance on a combined basis. Operating expense also benefited from a $23 million recovery of prior year's costs. We issued debt during the quarter to finance a portion of the Permian acquisition, and we are very pleased with our resulting capital structure, the maintenance of our investment grade rating, and stable outlook from all four credit rating agencies. At quarter end, our leverage ratio was 1.7x, which included all of the acquisition finance debt, but only 19 days of EBITDA from the acquired assets. We remain committed to our mid-cycle leverage target of one times or about $4 billion of total debt, assuming mid-cycle prices. The maturity profile of our recently issued bonds will allow us to optimize our debt pay down schedule as we work towards that target. While debt reduction is a big focus for us in the near term, our shareholder return framework has not changed. We will continue to distribute at least 50% of post-dividend free cash flow to our shareholders, with the remaining 50% going to the balance sheet. I would also like to note that the amount of cash available for buybacks in our shareholder return framework is determined each quarter on a discrete basis. Yesterday, we provided our third quarter guidance and updated our 2023 full year guide to reflect the efficiencies, cost savings, and improved well productivity we've seen year-to-date across the portfolio. In the third quarter, we expect total production to average between 540,000 to 560,000 BOE per day, with oil and condensate production of between 202,000 to 208,000 barrels per day. We expect oil and condensate production to continue to grow through the fourth quarter and average 210,000 barrels per day in the second half of the year. This reflects the production momentum from the new Permian assets as we bring acquired wells in progress online. The production profile will normalize by midyear 2024 with the second half of 2024 oil and condensate production stabilizing at 200,000 barrels per day. We also raised our full year natural gas guide due to strong well performance across the portfolio. Third quarter capital spending will be the peak for the year at $840 million to $890 million. This reflects the shift from a 10 rig program in the Permian at the time the acquisition closed to our current five rig program, and the capital associated with the higher level of activity as we work to bring the acquired WIPs online by year-end. We expect to bring online about 100 wells in the third quarter, with roughly half of these from the acquired Permian assets. We've updated our full year guidance with higher production and lower capital investment. The new guide incorporates the operational and capital efficiencies we've achieved, our strong well productivity performance, and the success we had in offsetting base production declines. In addition to increased capital efficiency, we also expect to see increased cash cost savings. We divested a relatively higher cost asset in the Bakken and added a relatively lower cost asset in the Permian. We anticipate company-level savings of approximately 5% on a combined basis for OpEx and T&P in the second half of the year. We also provided an update to our hedging positions with the materials yesterday, with about 50% of our WTI exposure and about 40% of our NYMEX gas exposure hedged for the next 12 months. Capital efficiency is a key focus across the organization, as efficiently converting our resources into cash flow is a crucial aspect of our durable returns approach. Ovintiv's capital efficiency ranks top tier among our peers and is creating exceptional value in today's volatile commodity and macroeconomic environment. In 2024, we expect to produce more than 200,000 barrels of oil and condensate per day for about $2.3 billion of CapEx at the midpoint. That's a 15% year-over-year capital efficiency improvement with an associated increase of 30,000 barrels per day of oil and condensate versus our original 2023 guide. This increase in capital efficiency generates higher returns on invested capital and allows us to deliver higher cash returns to our shareholders. When compared to our peers, Ovintiv's 2024 capital program will require about $250 million less capital to deliver the same production at the midpoint of our 2024 oil and condensate production and capital guides. I will now turn the call over to Greg to cover our operational highlights.

Thanks, Corey. As Brendan noted, our top priority over the last month and a half has been the efficient and seamless integration of the new Permian assets into our existing operations. And the team has done a very impressive job. With five rigs and three frac spreads currently running across 180,000 acres in the play, we are already at our run rate activity for the rest of the year. Our results in the Permian year-to-date have been stellar, and we are very excited to unleash our proven development model on the acquired acreage. The wells on the new acreage are performing in line with the average 2022 Midland Basin productivity rates, and we see opportunities to increase well performance and capital efficiency as we apply our drilling and completion approach to these assets. We have already begun deploying our proven optimization techniques on completion design, artificial lift, and accelerated cycle times on the wells that were already in progress when the acquisition closed. We are also streamlining planning and logistics across our combined Permian position, improving efficiency compared to the three separate operating companies that were previously planning and executing work on each of their individual footprints. We have already reduced offset frac hits as we've optimized our program across the combined position. As Brendan noted, we expect to see our first end-to-end Ovintiv designed wells online in the fourth quarter. Our efforts on completion design, particularly on stage architecture, continue to deliver leading well performance across our Permian acreage. The chart on the right shows the 2022 Midland Basin industry average compared to our 2023 type curve and the wells we brought online in the first half of the year. Our year-to-date oil performance is among the highest we've ever delivered in the Permian. It's important to note that the well outperformance is a result of the advances we've made to enhance completion design, including stage architecture, fluid chemistry, and proppant loading. Our cube development approach has stayed consistent and our program well spacing is unchanged year-over-year. These results were spread out across our acreage footprint, and our enhanced completions are being executed without an increase to completed well cost as we are able to deploy our leading efficiencies into making better wells. While the recent well performance is outstanding, we remain thoughtful with our go-forward type curve assumptions. In the third quarter alone, we will bring on more than 50% more wells than we did in the entire first half of the year in the Permian. Once we see the results from these completions as well as the longer-term production from the previous wells, we will have a much better handle on the repeatable uplift we can incorporate into our forecast. I'd like to take a quick moment to recognize the outstanding performance from our team in the Permian this quarter. Our operations continued to hit on all cylinders, setting new performance records while seamlessly integrating our newly acquired assets. These results are allowing us to deliver stronger well performance through completions optimization and improved stage architecture in a cost-effective manner. For example, our second quarter average completion speed at well over 3,500 feet per day is about 40% faster than our average speed over the last three years and 11% faster than our first quarter average. Using the same time frame comparison, we now pump 80% more proppant per day and 45% more fluid. Our enhanced performance is delivering better wells at lower cost, improving our capital efficiency. We continue to deliver impressive results across our portfolio, and our year-to-date performance in the Montney is no exception. Ovintiv wells continue to dominate the list of most productive wells in the play on a total BOE basis. Over the last 12 months, we have brought on the top 31 wells in the Montney and 36 of the top 50. I want to be clear that these impressive production rates do not come with a higher price tag. The average cost of the 36 wells highlighted in the chart was $4.5 million per well, making Montney wells the lowest cost in our portfolio. The great returns we generate in the play are further enhanced by our market diversification strategy, which we use to manage flow assurance and price risk. With almost all our Montney gas pricing outside of AECO, we realized 97% of NYMEX on a pre-hedge basis, and our condensate received 96% of WTI during the quarter. In the Uinta, we continue to deliver some of the strongest oil well results in North America. We recently brought on our 3 Well Jorgensen Pad in Duchesne County with strong IP30 rates of 1,850 barrels of oil per day per well. Our large contiguous land base of approximately 130,000 net acres has multiple benches with about 1,000 feet of collective pay. It is 80% undeveloped, which translates into a significant inventory runway. As we previously noted, we secured additional rail capacity to the Gulf Coast, and we currently rail about 30% to 40% of our volumes there. This scalable option supports our future development plans for the play. Due to the highly oily nature of this play in the first half of the year, the Uinta tied the Permian for the highest operating margin in our portfolio. Given the current gas and NGL markets, we’ve reduced our activity in the Anadarko Basin in the back half of the year. That said, the Anadarko is expected to be our top free cash flow generating asset in 2023 and remains a premier multiproduct option in our portfolio. The team continues to work the asset hard, cutting our base declines in half since 2021. They also wrapped up this year's activity on a high note, realizing a 25% increase in drilling feet per day in the quarter versus our 2022 average. I will now turn the call back to Brendan.

Thanks, Greg. And before we move to Q&A, I'd like to sum up the key takeaways from today's call. I'd like to commend our team for the outstanding results year-to-date. Our focus on execution excellence has shown up across our portfolio. We have successfully integrated the new Permian assets, and our team is already applying our development model to the wells in progress. The asset performance has been strong, and we see opportunities for further gains going forward. We are increasing full year 2023 production guidance and lowering capital spending. We are one of the most capital efficient operators in the industry, and our 2024 program is advantaged compared to our peers in its ability to deliver more barrels for fewer dollars. We are committed to debt reduction while returning significant cash to our shareholders. Our shareholder returns framework remains unchanged, and the amount available to shareholders will be determined by the same reliable approach every quarter. Over the long-term, we believe that value creation in the E&P space will come from companies that can durably generate both superior return on invested capital and return of cash to shareholders. We are well-positioned to deliver on this value proposition with a deep premium inventory, leading capital efficiency to convert that inventory to free cash flow, and disciplined capital allocation to ensure those returns flow through to the bottom line and to our shareholders. This concludes our prepared remarks. Michelle, we are now ready to open the line for questions.

Your first question comes from Arun Jayaram at JPMorgan. Please go ahead.

Yes. Good morning. Brendan, could you provide more insights into the well productivity gains you're experiencing, especially in the Permian? Greg mentioned stage architecture, fluid, and completion design, but I'd like to hear more about the potential for repeatability. Additionally, have you tested this in some areas beyond the core, and if so, do you have any preliminary results to share?

Yes. Arun, good morning. I appreciate the question and the pickup on the well performance. Obviously, I'm really excited about what we are seeing there. As we reported here today, we've now got 44 wells of the program online with production history, and the performance is well above our 2023 type curve, which we are obviously enthused about. Really, the driver we are seeing here is the completion design piece that you mentioned. This has been a multiyear effort by our team to zero in on the true causal factors that can drive well performance and increased recovery from shale. It's not just in the Permian, we're deploying this across the whole portfolio. I like to kind of break it down into three buckets in terms of what the team has been driving on. The three buckets we see really are the stage architecture, which is our phrase for the combination of cluster design, cluster spacing, and of course, the sand and water loading that we are feeding in through those clusters. The goal here is to create a more conductive fracture network more consistently placed along the entire lateral. That becomes more important as we drill longer laterals in these plays and drive efficiencies that way. So that's the first bucket. The second bucket is really about using the chemistry of the frac fluid to enhance the permeability of oil in that fracture network to get more recovery from the pore system. The final bucket includes real-time frac monitoring, where we aim to gather signals back subsurface while we are pumping to tune our frac design as we go. This enables us to be more efficient with that frac design while also maximizing recovery along that long lateral. So those are the three buckets I would speak to, Arun.

It sounds like a nice endorsement of how a smart fleet technology, Jeff Miller. My follow-up, Brendan, is have you tested this kind of completion design outside of the core? And could there be any implications for, call it, Tier 2 locations on the map where you could boost the overall productivity to perhaps mimic Tier 1 type of economics?

Yes. I don't have the slide number off the top of my head here, but the slide that shows the Permian type curve performance also shows the math of where those 44 wells are across our land base. You can see from that that these completion designs are working across the Permian for us. As far as the Tier 1, Tier 2 implications, what we are seeing is it's making the Tier 1 stuff better. Luckily, our acreage position is primarily in the core of the basin. We've really been just using it on the acres we have, which are largely in that Tier 1 bucket. However, moving locations from near premium to that premium bucket is a win and we look to do that all the time as well. One of the things we've talked about on the new acres is that 800 premium count underwrites three bench development across the acreage. Greg pointed out that we have quite a number of wells in progress that we will be bringing on stream, all of which are three or four bench cubes or even higher in some instances. So we are excited to see how those completion designs show up when we start to get them later this year.

Great. Thanks.

Your next question will come from Neal Dingmann at Truist Securities. Please go ahead.

Good morning. Thanks for the time. Brendan, my first question is on your forward plan, which seems quite good. Specifically, you talked about stabilizing your production, I believe. I'm just wondering if you would consider this kind of a maintenance plan? If so, could you maybe speak to the level of CapEx needed to sustain this?

Yes, Neal, I appreciate it. We reiterated that 2024 view here today, and obviously feel good about where that is sitting as we get further into the year and now actually have control of the new assets. We feel really good about that guide. The big movers are going to be how much deflation actually shows up. We think sitting here today with what we know about cost structure and activity levels that guide still makes total sense to us. The implied midpoint of capital for '24 and then settling in at that 200,000 barrels a day in the second half, make total sense. The only thing I'd add is we continue to think that's the right way to prosecute this business. We've talked about really three gates of decision making for capital allocation for either maintenance or modest growth. In order to even think about modest growth, the three gates for us would be, first, it would have to be a better cash flow per share outcome than simply buying our shares back. The second test would be whether the world needs more barrels and BTUs. The third test would involve assessing execution risk on adding that activity. The buyback still screens more favorably than adding rigs and spreads to the program. Our judgment today indicates that the world isn't asking for additional barrels and BTUs from us. Additionally, the execution risk from a year-over-year perspective feels a lot better than it did last year when inflation was running hard.

Yes. Agree. All that makes sense. That's certainly to me as well. And my second question maybe for Greg, on the Permian. Specifically, can you address future potential maybe frac hits or needed well shut-ins? It seems like the plan you guys have talked about even now post-deal has much more minimum levels of shut-ins compared to a number of your peers that are experiencing this.

Yes, Neal, thanks for the question. You're exactly right. That was one of the value propositions we saw with the acquisition we just closed. You had three companies that were doing a good job but operating independently. Because of that, they weren't able to coordinate schedules, leading to knocking off wells shortly after they were brought online. What we've already seen, as I mentioned in my prepared remarks, is that by using a coordinated approach across the entire 180,000-acre footprint we now have, we've already seen a reduction in frac hits, allowing us to fully benefit from all the fracs that we are currently pumping without knocking these newer wells offline. We'll continue to optimize this going forward, but we feel this is a big part of the value we can bring to this acreage.

No. Great to hear. Thanks, Greg. Thanks, Brendan.

Your next question will come from Gabe Daoud at TD Cowen. Please go ahead.

Hey, thanks. Good morning, everyone. Maybe just back to the Permian outperformance. Greg, could you maybe just comment on what exactly you need to see here or how much time and data do you need to collect to start factoring in performance into your go-forward guidance? I guess it would depend on what some of these new cubes look like on the new acreage, but I’m curious to hear your thoughts on that. And then could you also just comment on where pro forma Permian production is today? I think at the time of the deal, you pointed to 125,000 barrels a day of oil & condensate combined. So curious if that's more or less where you're at today.

Yes. As far as the forecasting goes, we've had a lot of activity in the play today. We are very pleased with what we saw in the first half and those wells continue to hold up. We will be bringing on a lot more wells in the back half of the year. We will want to see how that productivity holds up, keeping in mind that over half the wells we're bringing online in the third quarter were wells that, while we are influencing the tail end of the completion, we were not involved in these wells from their inception to bringing them online. So we do believe there's a bit of uncertainty there. We want to see how those wells perform. We're quickly incorporating all of our completion techniques into operations, so you're going to see a lot of data coming in as we move through the third and into the fourth quarter. By the end of this year, we should have a much better sense of how well the uplift is impacting our existing legacy portfolio, the new wells, and how long this production uplift holds up. The volume is fairly dynamic, and we are currently just a little over that 120,000 barrel a day mark.

Got it. Got it. Okay. Cool. Thanks, guys. That's helpful. And then just a quick follow-up on the cost side, you highlighted some of the efficiencies driving savings, and you have that $2.1 billion to $2.5 billion range out there for 2024. But curious what is embedded in that $2.1 billion? If efficiencies continue to hold, could that number trend towards $2.1 billion? Or is there a bit of expectations around some cost deflation continuing? Just curious if you could maybe talk a little more about what we need to see for that $2.1 billion number.

Yes, Gabe, I appreciate it. I think the service cost environment is probably the bigger driver of the range there as we see it sitting here today. The midpoint of the range feels like the right steering point with what we know. We'll have to see where service prices trend. We've seen rig counts come down on both the gas and oil side by about 15% from the peaks. If that trend continues, it will keep driving further deflation and could push us lower in the range. We will observe, of course, oil has ticked up a bit, and gas could be a bit stronger through the summer months. However, we are clear about not adding activity, so we will have to see how things unfold across the rest of the industry. We will tune our '24 guidance as we get closer to it.

Thanks, guys.

Yes, thank you.

Your next question will come from Joshua Silverstein at UBS. Please go ahead.

Yes. Thanks. Good morning, guys. Just thinking about the shareholder return profile versus the debt reduction you mentioned, kind of up to 50% for the balance sheet portion of it. Do you basically have enough cash on hand to pay down the 2025 and 2026 maturities as they come up, or do you actually want to build a little bit more cash than that to be opportunistic for other bolt-ons or anything else?

Yes. I think what we will do is we will follow the program here, which calls for at least to incremental shareholder return over and above the base dividend. The remainder will be available for debt reduction, which we are trying to take down to $4 billion. We will be opportunistic as we go along and were thoughtful about the capital structure to enable that without extra costs. We have some well-timed maturities in the next couple of years to manage that.

Got it. And then it seems like you have a good well performance there. I was curious about the rail infrastructure mentioned. Is this supporting potential basin growth for you guys, an increased capital allocation, or is it really just a cost-efficient play?

Yes. We are excited about what we see in the Uinta. Remember, over the last two years, we've worked hard to demonstrate well performance at cube development spacing and unlock that market access to the Gulf Coast. We're now railing to the Gulf about 30% to 40% of our total volumes, and with two rigs running there, we expect to see significant production ramp in the Uinta through the back half of the year. This rail infrastructure is low cost and scalable, enabling higher Uinta production volumes this year and into 2024, depending on how we allocate capital in '24.

Got it. Thanks.

Yes, great. Thanks, Josh.

Your next question will come from Doug Leggate at Bank of America. Please go ahead.

Good morning. This is John on for Doug Leggate. Our questions really are on the Anadarko Basin. First of all, with the reduction of activity, what would you have to see in terms of prices to bring the activity back to that basin?

Hey, John. Yes, good morning. The Anadarko team has done an incredible job. Their focus on innovation has resulted in a substantial shallowing of our base decline to 20%. That creates a lot of value for us and means it's set to be our highest free cash flow generator in the portfolio. The recent wells the team has brought online have been really strong performers. We've been utilizing the same completion design optimizations in the Anadarko as in the Permian. However, the current gas and NGL fundamentals coming into the second half of the year are why we chose to rotate capital out of there for the time being. With stronger gas and NGL fundamentals expected in 2024, particularly later in the year once we see the start of some incremental LNG pull off the Gulf Coast, that might signal bringing capital back into the Anadarko and returning the rigs there. I think we'll just watch for it; I can't specify a single price toggle. It will largely depend on cost structure as well.

That's very helpful. And just as a quick follow-up on the Anadarko. Given the improvements in the underlying declines and productivity you see, how long do you think you can actually maintain that flat if you wanted to?

Yes. The great thing about the Anadarko is we've got a deep, high-quality inventory in that play. We see over a decade of drilling inventory to hold that asset flat should we choose to allocate the capital there.

All right. Thank you very much.

Thanks, John.

Your next question will come from Umang Choudhary at Goldman Sachs. Please go ahead.

My questions. I appreciate all the color on the strong performance in the Permian and the Montney. I understand there's less clarity in terms of how the 3Q performance will shape up in the Permian in the acquired assets. Can you remind us of the cadence of activity in the back half of this year, especially in the Permian? I'm trying to pare the improved performance you've seen recently in your legacy assets and the implications for your production guidance next year.

Yes, I appreciate it. As for cadence, there’s a lot going on in the Permian in the back half of the year. We will see between 60 and 70 TILs in the third quarter, and just a little less than that in the fourth quarter, but still high. This sets us up at a total company level to average 210,000 barrels a day of crude and condensate in the back half, with some of that production spilling into early 2024. We expect to level out at that 200,000 barrels a day by midyear and maintain that throughout the second half. That’s our cadence outlook.

Got you. That's really helpful. My next question is about risk management. As you mentioned earlier, you added some leverage with the transaction. Do you have any updated thoughts on the level of hedging you want to implement to protect against commodity price risk next year?

Yes. On hedging, we've continued to use our next 12-month approach, building the book out one quarter at a time. We've also continued to use three-way structures to provide a soft floor that we are comfortable with while also providing some upside to higher price exposure, enabling us to participate in a more favorable market. In the second quarter, we added some second quarter '24 hedges on the gas side. Over the next 12 months, we are about half hedged on oil and about 40% hedged on gas, primarily using those three-way structures. As we continue to drive debt down, we'll lower that hedging level down from roughly 50% and 40% toward a more quarter to a third of our production level.

Got it. Thank you so much.

Thank you.

Your next question will come from Phillips Johnston at Capital One. Please go ahead.

Thanks. In addition to the uplift in productivity you're seeing in this year's vintage of wells in the legacy Midland properties, you mentioned older wells are outperforming forecast. Just wondering the kind of magnitude you might be talking about there. What would you trim that to? And which areas are you seeing the biggest upside?

Yes, Phil, great pick up. That's one of the most efficient ways to add production, optimizing the base. Contributing factors here include our work on artificial lift and some inexpensive workover treatments that have been boosting our older vintage wells, which we're excited about. Greg, do you want to add anything?

Yes. It's a lot of great work by our teams, blocking and tackling, reducing failure frequency. We see a bit of improvement with some of the new frac designs we are implementing, which seem to have less impact on the parent wells. A lot of factors adding up to a nice little beat here on the base side. We're focused on this in all areas, not just the Permian.

Okay. I'm guessing that's not factored into your second half production guidance or the '24 guidance, correct?

Well, what we've factored in is the performance uptick we've seen on the existing PDP. The upside still comes from further decline abatement, but we've included the PDP impacts we're realizing today in the forward guide.

Okay. That makes sense. And then just an update on LNG Canada Phase 1. I realize you guys aren't a direct participant, but it's obviously going to help pricing in the region. I think as of the Montney Day in September, the project was over 60% complete with timing in first quarter '25. Just wondering how progress has been since then?

Yes. I'll get Corey to chime in because there have been some recent progress updates from the operators there, both on the pipe side and the LNG liquefaction side. He might remember the percentages, but it sounds positive.

Yes, sure, Brendan. Shell talked about this a bit recently. They're referencing over 75% completion on the midstream and more than 90% on the pipeline. That’s good news.

Okay. That sounds good. Thanks.

Thanks, Phillips.

Your next question will come from Jeoffrey Lambujon at TPH & Co. Please go ahead.

Good morning, everyone, and thanks for taking my questions. My first one is another one on how you're looking at forecasting for next year. If we get to a situation where the current forecast for the Permian particularly proves conservative for 2024, perhaps the same CapEx range you've been discussing could actually yield more production than what's modeled today. How should we think about the overall outlook potentially changing? Should we expect reductions to the spending range with less capital needed for greater production, or might it be safer to view it as a steady range on CapEx but with potential for volumes sold closer to what we see in Q4 for a bit longer?

Yes, Jeoff, I appreciate the question. As we set '24, we will run our three gates model on cash flow per share impacts, the world’s demand for barrels and BTUs, and execution risk. Sitting here today, maintenance level still feels like the right approach, but we'll reassess as we move through the second half of the year. We have worked hard to create a level loaded program this year, which we want to preserve going into 2024. Those will be the main factors we weigh as we proceed and optimize both return on invested capital and return of cash to shareholders.

Okay, great. My second question is just a follow-up on the Uinta. Given we’re about to see some additional contributions from that asset in the second half, I wanted to know what you need to see to allocate more capital there. You’ve discussed productivity and the infrastructure making room for that if you choose to allocate capital there. Could you refresh us on the competitiveness of that asset going into next year versus the balance of the portfolio?

Yes, currently the program we have for the rest of '23 is return competitive with the rest of our portfolio. It sits on par with returns we are seeing in other plays, which is essential because otherwise we wouldn't allocate capital there. With two rigs in play, we expect a substantial ramp in volumes, which feels right for '24. We will keep an eye on performance as we move through the year.

Perfect. That’s all.

Yes. Thank you, Jeoff.

At this time, we have completed the question-and-answer session, and I will turn the call back to Mr. Verhaest.

Thanks, Michelle, and thank you, everyone, for joining us today. Our call is now complete.

Ladies and gentlemen, this concludes your conference call for this morning. We would like to thank everyone for participating and ask you to please disconnect your lines.